Predicting Foamy Oil Recovery

Abstract

Abstract With a current recovery of only 5 percent, Albania's largest oilfield Patos-Marinza, first commercially produced in 1939, still yields a potential of more than 100 MMbbl reserves of 10 - 12°API oil from a depth of 1600 m. A consortium consisting of the Albanian Albpetrol, the German Preussag Energie, the British Premier Oil, and the IFC, the private sector arm of the World Bank, are making plans to improve oil recovery. Testing wells producing 1–2 m3/d yielded rate improvements with Progressive Cavity Pumps up to 30 m3/d with sandcuts around 10 to 35 %. PVT analysis of the oil with a relatively high solution-GOR of 35 m3/m3 shows a strong tendency to foam (gas in microbubbles without forming a continuous gas phase) below the bubble point, near the initial reservoir pressure. Core tests with different depletion rates resulted in primary oil recoveries of greater than 30 %. For predicting project recovery and eonomics a black oil simulation model was built with ECLIPSE on the basis of the lab results. The sand production was inferred through channels laid out in a star-like manner with a single cross connection. Constructing type wells a sensible forecast including sand was attained. The paper discusses all measurements and results in the context of present theories of foamy oil and Cold Heavy Oil Production (CHOP). Introduction The Patos-Marinza Oilfield is an onshore field located east of the city of Fier in South Central Albania (Fig. 1). It occupies an area of approximately 24,000 hectares and was discovered in 1926 starting commercial oil production in the early 1930's. Development to the north continued with drilling over 2300 wells, reaching the boundaries of the field in the late 1980's. The main sandstone reservoirs dip at 8 - 13° from an outcrop in the South containing mineable tar sands to the oil water contacts at 1800 m in the north. There are multiple stacked sand reservoirs of Upper Miocene (Messinian) age, the most important ones being Gorani, Driza, and Marinza (top to bottom). The Driza reservoir contains the majority of OOIP and reserves. It consists of up to 6 sand layers numbered from top to bottom, with the D1 being the main sand continuous throughout the field. The Driza is a suite of unconsolidated sandstones with porosity of 25 - 28 % and net pay varying areally from 7 to 95 m (south to north). Oil gravity also varies throughout the field depending on the depth of the reservoir and the type of formation. Marinza oil (north) has a gravity up to 825 kg/m3 (40°API) due to greater depths and an areally closer position to the source rock. The oil gravity in the Patos area (southern half of the field) is about 998 kg/m3 (11°API) with dead oil viscosity over 9000 mPa s under reservoir conditions. Due to the unfavorable fluid properties oil recovery to date amounts to less than 5 % under depletion drive. The wells with a 2.5 acre spacing generally produce less than 1 m3/d oil with tubing insert pumps landed halfway to bottom due to equipment limitations. Anglo Albanian Petroleum Ltd., the operator of the consortium, performed tests with progressive cavity pumps (PCP) to improve the oil recovery. Setting the pumps below the perforated D1-sand resulted in production rates up to 30 m3/d heavy oil together with 15 – 35 % sandcut, greatly exceeding calculated values. The tests provided initial rates and sand production, but were not long enough to establish any declines. With the experience of Canadian oilfieldsi, the analogy was drawn to the cold heavy oil production mechanism (CHOP) currently investigated by numerous institutions. For estimating future production and ultimate recovery, a commercially available simulator was employed, incorporating foamy-oil PVT data and Canadian cold heavy oil production experience to infer channel development.